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With the number of extended-reach wells steadily increasing, software modeling has become a commonplace and essential process during a well's planning phase. Over the years, numerous computer programs have been developed to predict torque and drag (T&D) forces experienced during oilfield drilling and completion operations. Accurate prediction of T&D forces can reduce serious drilling operation risks such as buckling, pipe failures, box swelling and the inability to get liners and casing to total depth (TD).Most, if not all, industry available T&D software programs allow users to manipulate inputs such as friction factors, mud weight, and string component parameters, such as pipe weight, grade and dimensions. While the ability to alter the inputs in the T&D model is a practical necessity, the possibility of unknowingly impacting the calculations is an ever present danger. In addition to a thorough knowledge of how to input well parameters and analyze outputs, it is crucial for program users to question the reliability of each program and to understand the impact that changes in inputs have on the model's outputs. This paper will describe the technical differences between two T&D modeling programs, the underlying calculations, and the practical implications in terms of calibrating the two models to the same sets of field data. This paper also endeavors to increase knowledge and competency for T&D software users in the oil and gas industry.

Drilling more efficiently has always been an important consideration throughout the industry, but with the ever more complex and far reaching wells that are being drilled today, it has reached the stage of being a critical factor in the economic viability of many projects. This has lead to the development of many tools and techniques which have enhanced the overall process of drilling deviated wells and helped to realize significant savings in drilling time and improvements in well geometry. Two such developments are the adjustable gauge stabilizer (AGS) and torque-and-drag reduction tools, which provide a method of reducing drilling times in directional wells with build and tangent sections, thereby decreasing the cost while mitigating risk. An AGS eliminates the need to pull and replace the bottomhole assembly (BHA) after completing the build section, thereby saving one complete round trip. Torque-and-drag reduction tools enhance the ability to make directional adjustments while rotating and facilitate reaching well targets which high levels of torque and drag would otherwise prevent. As a result, the time spent drilling with a positive displacement motor (PDM) without pipe rotation (sliding) in the tangent section is mitigated, reducing overall drilling time for the section by an average of at least 20%. This paper will discuss the evolution, design and operational characteristics of these tools and will present case studies of wells drilled in Ecuador where either the application of both adjustable-gauge stabilizers and torque-reduction tools, or the application of an AGS reduced drilling time when compared to offset wells drilled with conventional directional assemblies.

INTRODUCTIONWith the global trend moving toward drilling deep water wells, ultra-extended reach wells (u-ERW) and complex geometry wells, we can no longer ignore the drilling limitations caused by high torque and drag forces. Extreme torque and drag, especially unplanned, can be detrimental to drilling operations. Over the years, engineers have developed numerous ways to challenge the drilling limitations by reducing torque and drag forces in order to drill further and deeper. This paper attempts to describe the practices and the evolution of torque and drag reduction methods. The different torque and drag reduction methods that this paper focuses on are listed below.

Long horizontal laterals with challenging well geometries and fracturing operations with 20-30 stages are commonplace in the US. Planning for successful completions operations that push the envelope of equipment and lateral reach is critical, and the ability to more accurately account for drag prior to running swell packers and frac sleeves downhole is needed to assist with the reliability of completions operations. This paper will include an in depth look at the rig data, torque and drag models and the post job friction factors, which are an overall indication of the hole condition, for six wells. The post-job friction factors will be calibrated for drilling the final hole section and running the completions string, then analyzed to consider a link between the two operations. Production data will also be taken into account.By creating a database of friction factors for completions operations that consider completion type, fluids used, use of centralizers, lithology and work string data, past experience has shown that even offset wells in the Bakken can have significantly varying amounts of drag. Analyzing the friction factors for drilling the final hole section will provide an opportunity to predict the level of drag prior to running the completions string. This paper will provide the torque and drag analysis of both the drilling and completions operations for seven wells, along with a method to link the two operations. Conclusions will be drawn related to the variance between wells and the ability to predict the success of running completions strings to TD after gathering the hookload data and calibrating a post-job friction factor for the final drilled section of a well.Although the results of the analysis will best apply to shale plays with similar geometries, the work method presented in the paper is applicable to any well construction scenario.